DELIVERED FULL YEAR EBITDA OF $373.2 MILLION, UP 117% COMPARED TO 2020 AND AVERAGE PRODUCTION OF 37,818 BOE/D, IN-LINE WITH 2021 GUIDANCE
RECORDED NET INCOME OF $628.1 MILLION IN 2021 AFTER IMPAIRMENT REVERSALS
REPORTED A YEAR END CASH POSITION OF $320.8 MILLION AND RELEASED $105.6 MILLION OF RESTRICTED CASH
COMPLETED PIPELINE CONCILIATION AGREEMENT ELIMINATING MORE THAN $1 BILLION IN CONTINGENT LIABILITIES
REPURCHASED 3.86 MILLION COMMON SHARES, OR 7.4% OF THE PUBLIC FLOAT FOR CANCELLATION FOR $21.5 MILLION UNDER CURRENT NCIB PROGRAM
ACHIEVED 98% OF 2021 ESG GOALS, OFFSET 41% OF EMISSIONS THROUGH CARBON CREDITS, PRESERVED AND RESTORED 765 NEW HECTARES OF KEY CONNECTIVITY CORRIDORS IN CASANARE AND META, COLOMBIA
CONFIRMED ~200 FEET OF NET PAY WITHIN MULTIPLE HORIZONS AT KAWA-1 EXPLORATION WELL IN GUYANA
CALGARY, AB, March 2, 2022 /CNW/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") today reported financial and operational results for the fourth quarter ended December 31, 2021. All financial amounts in this news release are in United States dollars, unless otherwise stated.
Gabriel de Alba, Chairman of the Board of Directors, commented:
"Frontera continues to deliver on its strategic, operational and financial objectives. In 2021, Frontera generated operating EBITDA of $373.2 million, an increase of 117% compared to 2020 and within the Company's tightened and increased full-year operating EBITDA guidance range. Frontera also averaged 37,818 boe/d, in-line with 2021 guidance. Frontera's production costs averaged $11.46/boe and its transportation costs averaged $10.43/boe, both within 2021 guidance ranges. The Company reported a year end cash position of $320.8 million and released approximately $105.6 million of restricted cash. Frontera increased its uncollateralized credit lines to $89.6 million at year-end and repurchased approximately 3.86 million common shares, or 7.4% of the public float, for cancellation for approximately $21.5 million under its current NCIB as of December 31, 2021."
Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented:
"Frontera delivered strong fourth quarter results. Production averaged 38,605 boe/d, up 6% compared to the previous quarter and the Company's year-end production exit rate was 40,457 boe/d excluding Petrosud. Frontera's daily production on March 1, 2022 was approximately 42,000 boe/d and the Company's year-to-date average to March 1, 2022 is approximately 40,500 boe/d. Compared to the previous quarter, cash provided by operating activities in the fourth quarter increased by 43%, the Company's operating netback increased 26%, the Company's net sales realized price increased 17% and the Company's transportation costs decreased 12%.
During the fourth quarter, Frontera began early production of ~2,400 boe/d (gross) at the La Belleza discovery on VIM-1, completed the Conciliation Agreement with Cenit and Bicentenario which eliminated more than $1 billion in contingent liabilities, acquired 100% of the issued and outstanding shares in Petroleos Sud Americanos S.A. which added ~1,300 boe/d production and signed an agreement to acquire the remaining 35% interest in el Dificil block held by PCR Investments S.A., adding an additional ~500 boe/d of production when the deal closes in the second half of 2022. Subsequent to year end, we discovered hydrocarbon bearing reservoirs in multiple formations at the Jandaya-1 exploration well in Ecuador and we were awarded Block VIM-46 in the 2021 Colombia Bid Round. Importantly, we discovered approximately 200 feet of net pay within multiple horizons at the Company's potentially transformational Kawa-1 exploration well, offshore Guyana."
Fourth Quarter 2021 Operational and Financial Summary
Heavy crude oil production
Light and medium crude oil production
Total crude oil production (1)
Conventional natural gas production (1)
Natural gas liquids (1)
Total production (2)
Oil and gas sales, net of purchases (4)
Realized (loss) gain on risk management contracts
Net sales realized price (5)
Production costs (6)
Transportation costs (7)
Operating netback (4)
Oil and gas sales, net of purchases (4)
Realized (loss) gain on risk management contracts
Net sales (4)
Net income (loss)(8)
Per share – basic
Per share – diluted
General and administrative
Operating EBITDA (4)
Cash provided by operating activities
Capital expenditures (9)
Cash and cash equivalents - unrestricted
Restricted cash short and long-term
Total debt and lease liabilities
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) (4)(10)
Net Debt (Excluding Unrestricted Subsidiaries) (4)(10)
Reference to heavy crude oil, light and medium crude oil combined, conventional natural gas or natural gas liquids production in the above table and elsewhere in this MD&A refer to the heavy crude oil, light and medium crude oil combined, conventional natural gas, and natural gas liquids, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101").
Represents W.I. production before royalties and total volumes produced from service contracts. Refer to the "Further Disclosures" section on page 36 of the MD&A.
Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. Refer to the "Further Disclosures - Boe Conversion" section on page 36 of the MD&A.
Non-IFRS financial measures. Refer to the "Non-IFRS Financial Measures" on page 11 of this press release and the "Non-IFRS Measures" section on page 22 of the MD&A. This section also includes a description and details for all per boe metrics included in operating netback.
Per boe is calculated using sales volumes from development and producing ("D&P") assets. Volumes purchased from third parties are excluded.
Per boe is calculated using production.
Per boe is calculated using net production after royalties.
Net income (loss) attributable to equity holders of the Company.
Capital expenditures include costs, net of income and cost from exploration and evaluation ("E&E") assets.
"Unrestricted Subsidiaries" include CGX Energy Inc.("CGX"), Frontera ODL Holding Corp., including its subsidiary Pipeline Investment Ltd. ("PIL"), Frontera BIC Holding Ltd., Frontera Bahía Holding Ltd., including its subsidiary Sociedad Portuaria Puerto Bahía S.A. ("Puerto Bahia").
Fourth Quarter Operational and Financial Results:
- Production averaged 38,605 boe/d, up 6% compared to 36,422 boe/d in the prior quarter and 41,945 boe/d in the fourth quarter of 2020. In 2021, Frontera averaged 37,818 boe/d, in-line with the Company's 2021 guidance of 37,500-39,500 boe/d compared with 47,800 boe/d in 2020. See the table above for production by product type for the prior quarter, fourth quarter of 2020, and year end 2021 and 2020. Frontera's year-end production exit rate was 40,457 boe/d excluding production from the Petrosud acquisition. Frontera's daily production on March 1, 2022 was approximately 42,000 boe/d consisting of approximately 21,500 bbl/d of heavy oil, 17,850 bbl/d of light and medium crude oil, 9,400 mmcf/d of conventional natural gas and 1,000 bbl/d of natural gas liquids. The Company's year-to-date average to March 1, 2022 was approximately 40,500 boe/d consisting of approximately 21,000 bbl/d of heavy oil, 16,850 bbl/d of light and medium crude oil, 9,400 mmcf/d of conventional natural gas and 1,000 bbl/d of natural gas liquids.
- Operating EBITDA was $148.3 million in the fourth quarter compared with $72.6 million in the prior quarter and $35.6 million in the fourth quarter of 2020. The increase in operating EBITDA quarter over quarter was primarily a result of two more cargoes sold during the fourth quarter of 2021. Frontera generated $373.2 million of EBITDA in 2021, up 117% compared to $172.3 million in 2020. Frontera's $373.2 million of EBITDA in 2021 was within its 2021 EBITDA guidance of $360 - $380 million.
- The Company reported a total cash position of $320.8 million at December 31, 2021 compared to $419.5 million at September 30, 2021. Cash utilization during the period included $39.6 million of debt service and interest, $8.5 million in the Petrosud acquisition and $6.2 million to repurchase shares.
- The Company's restricted cash position was $63.3 million at December 31, 2021 compared to $100.7 million in the third quarter of 2021, a release of approximately $37.4 million. The decrease in restricted cash quarter over quarter is primarily due to the release of approximately $28.9 million related to a pipeline settlement agreement that was approved on November 11, 2021 (the "Conciliation Agreement"). In 2021, the Company released approximately $105.6 million of restricted cash. The Company anticipates releasing additional restricted cash in the second quarter of 2022 as the Company continues to optimize its credit lines.
- Cash provided by operating activities was $113.5 million in the fourth quarter of 2021, compared with $79.1 million in the prior quarter and $42.1 million in the fourth quarter of 2020.
- At December 31, 2021, the Company had a total inventory balance of 807,061 bbls compared to 1,423,321 bbls at September 30, 2021. Sales volumes, net of purchases in the fourth quarter increased by 46% compared with the prior quarter, reducing the inventory volumes in Colombia in the quarter.
- The Company has various uncommitted bilateral credit lines. As of December 31, 2021, the Company had increased its uncollateralized credit lines to $89.6 million, an increase of $69.6 million compared to December 31, 2020. Subsequent to the quarter, the Company increased its credit lines by approximately $16 million.
- Under the Company's current Normal Course Issuer Bid ("NCIB") which commenced on March 17, 2021 and ends March 16, 2022, the Company repurchased for cancelation 989,300 common shares during the fourth quarter of 2021 at a cost of approximately $6.2 million. As of March 1, 2022, the Company has repurchased approximately 4.1 million common shares for cancellation for approximately $23.0 million with an additional approximately 1.1 million common shares available for repurchase under the NCIB. The Company intends to renew its NCIB when it expires on March 16, 2022, to permit purchases for up to 10% of its public float over the next year. There can be no assurance that the Company will renew or complete its NCIB program as it remains subject to the Board's discretion based on the Company's financial position and outlook at the time and acceptance by the Toronto Stock Exchange.
- Capital expenditures were $135.5 million in the fourth quarter of 2021, compared with $103.2 million in the prior quarter and $24.9 million in the fourth quarter of 2020. The Company executed approximately $314.3 million in total capital spending in 2021 compared to $108.1 million in 2020. The increase in capital expenditures in the fourth quarter compared to the prior quarter was primarily due to increased operational activity as the Company drilled 14 development wells and increased exploration activity in Guyana, Colombia and Ecuador. The Company's $314.3 million total capital spending in 2021 exceeded its 2021 capital guidance of $245-$295 million.
- The Company recorded net income of $629.4 million or $6.60/share in the fourth quarter of 2021, compared with net income of $38.5 million or $0.40/share in the prior quarter and net income of $48.6 million or $0.50/share in the fourth quarter of 2020. Net income for the year was $628.1 million or $6.50/share in 2021, compared with a net loss of $497.4 million or $5.13/share in 2020. The increase in net income quarter over quarter was mainly due to the reversal of impairments, the recognition of additional deferred tax assets, the increase in Brent oil prices and additional volumes sold at the end of the year. The increase in net income year over year was mainly due to the reversal of impairments and the recognition of additional deferred tax assets.
- The Company's operating netback was $47.80/boe, up 26% compared with $37.79/boe in the prior quarter and $13.57/boe in the fourth quarter of 2020 primarily due to higher net sales realized price and reduction in transportation costs mainly due to the recognition of prepaid services of the Bicentenario system, partially offset by the increase in production costs mainly due to additional higher well services, maintenance activities, and the increase in power generation and communities costs.
- The Company's net sales realized price was $69.53/boe in the fourth quarter, up 17%, or $10.06/boe, compared to $59.47/boe in the prior quarter and $37.88/boe in the fourth quarter of 2020. The increase was primarily driven by higher Brent oil prices, higher volumes sold, lower costs of risk management contracts and lower royalties per boe during the fourth quarter of 2021.
- Production costs averaged $12.71/boe in the fourth quarter of 2021, up 11% compared with $11.44/boe in the prior quarter and $12.95/boe in the fourth quarter of 2020.The increase in production costs was mainly due to additional well services, maintenance activities, and the increase in power supply and community costs. Frontera's production costs averaged $11.46/boe in 2021, at the high end of its 2021 guidance range of $10.50-$11.50/boe.
- Transportation costs averaged $9.02/boe, down 12% compared with $10.24/boe in the prior quarter and $11.36/boe in the fourth quarter of 2020. The decrease in transportation costs was mainly due to the recognition of prepaid services of the Ancillary Agreements paid in 2020 as part of the implementation of the Conciliation Agreement, termination of the take or pay contracts for the Monterrey - El Porvenir pipeline, and the offloading facilities in Monterrey, Santiago and Oleoducto de Los Llanos Orientales ("ODL"). Frontera's transportation costs averaged $10.43/boe, within its 2021 guidance range of $10.00-$11.00/boe.
- The Company recorded a realized loss on risk management contracts of $6.7 million in the fourth quarter of 2021 compared to a realized loss of $6.6 million in the third quarter of 2021 and a loss of $8.2 million in the fourth quarter of 2020. The realized loss on risk management contracts was primarily due to the cash settlement on three-way collars, puts and put spreads contracts paid during the quarter at an average price of $79.66/bbl. Subsequent to December 31, 2021, the Company entered into new put hedges totaling 2,640,000 bbls to protect 2022 estimated production up to September 2022 at a $70/bbl strike price, and upgraded 565,000 bbls existing hedges as of December 31, 2021 from a $60/bbl strike price to $70/bbl strike price. The Company's first quarter 2022 hedges do not materially cap upside price potential. See the Hedging Update section below for more information.
- In 2021, Frontera implemented its "Building a Sustainable Future" ESG strategy and achieved 98% of its ESG goals for the year. The Company neutralized 41% of its emissions through carbon credits and preserved and restored 765 new hectares of key connectivity corridors in Casanare and Meta Departments, Colombia. It was awarded the Equipares Gold Seal for the Company's commitment and efforts to close gender gaps in the workplace and in the communities where it operates, increased the purchase of local goods and services to $40 million, recorded a total reportable incident rate of 1.70 and was recognized in 2021 for the first time as one of the World's Most Ethical Companies by Ethisphere. See below for more information.
CGX and Frontera, the majority shareholder of CGX and joint venture (the "Joint Venture") partner of CGX in the petroleum prospecting license for the Corentyne block offshore Guyana, have safely completed exploration activities at the Kawa-1 exploration well. In line with our exploratory objectives, the well has now been safely plugged and abandoned and the Maersk Discover drilling rig has been released from the Kawa-1 location. Only a single lost time injury was recorded throughout Kawa-1 well operations. The final cost of the Kawa-1 exploration well was $141 million.
The Kawa-1 well was drilled to a total depth of 21,578 feet (6,577 metres) in the northern section of the Corentyne block. Drilling results confirm the presence of an active hydrocarbon system at the Kawa-1 location. Successful wireline logging runs confirmed net pay of approximately 200 feet (61 metres) within Maastrichtian, Campanian, Santonian and Coniacian horizons. These intervals are similar in age and can be correlated using regional seismic data to recent successes in Block 58 in Suriname and Stabroek Block in Guyana.
The Joint Venture did not get MDT data or sidewall core samples and has engaged an independent third-party to complete further detailed studies and laboratory analysis on drilling cuttings from the Santonian, Campanian and Maastrichtian intervals and well-bore fluid samples to evaluate in situ hydrocarbons. Preliminary results from the Santonian interval indicate the presence of liquid hydrocarbons in the reservoir. Results from the Campanian and Maastrichtian intervals are pending.
Kawa-1 well results have improved the Joint Venture's understanding of the operational and geological complexities of the basin and will help reduce the technical risks of the Wei-1 exploration well. Given the initial positive results at the Kawa-1 well the Joint Venture is moving forward with its second exploration well, Wei-1 on the Corentyne block.
The Joint Venture has begun the integration of detailed seismic and lithological analysis and pore pressure studies from the Kawa-1 well into drilling preparations in advance of spudding the Wei-1 exploration well which will be spud in the second half of 2022. The Wei-1 exploration well will target Campanian and Santonian aged stacked channels in the western fan complex in the northern section of the Corentyne block. Data from both the Kawa-1 and Wei-1 wells will inform future activities and potential appraisal/development decisions.
On February 14, 2022, the Joint Venture announced that as a result of the initial positive results at the Kawa-1 exploration well, the Joint Venture will focus on the significant exploration opportunities in the Corentyne block and will not engage in drilling activities on the Demerara block in 2022.
CGX is currently assessing several strategic opportunities to obtain additional financing to meet the costs of the drilling program.
Frontera's daily production on March 1, 2022 was approximately 42,000 boe/d and the Company's year-to-date average to March 1, 2022 was approximately 40,500 boe/d.
Currently, the Company has five drilling rigs and five workover rigs active at its Quifa, Coralillo, Corcel, Copa and Guaduas operations in Colombia and at the Perico block in Ecuador. In the fourth quarter of 2021, the Company drilled 14 development wells including 12 at Quifa, and 2 at Guatiquia and completed 56 workovers and well services at Quifa, Guatiquia, Canaguaro, Abanico, Corcel, Cajua, Cravoviejo, Cubiro and Casimena. In 2021, the Company drilled 42 producer wells, 3 injector wells and completed 148 workovers and well services.
Production at Key Fields
At Quifa, current production is approximately 16,100 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company drilled 12 development wells at Quifa in the fourth quarter of 2021 and 25 development wells and 2 injector wells in 2021. Frontera also continued to recover water disposal levels in the fourth quarter by performing interventions in some water disposal wells at different injection layers.
At Guatiquia, current production is approximately 9,400 bbl/d of light and medium crude oil. The Company successfully completed the Coralillo-9 well during the quarter which is currently producing 700 bbl/d. Frontera also completed Coralillo-15 in the fourth quarter which began production of 600 bbl/d in January 2022.
At CPE-6, current production is approximately 5,000 bbl/d of heavy crude oil. In the fourth quarter, Frontera began operations on its facilities expansion strategy which is expected to handle up to 120,000 bbl/d and over 5,000 bbl/d.
On the VIM-1 Block (Frontera 50% W.I., non-operator), production from the La Belleza discovery began on November 8, 2021 with gross rates of approximately 2,400 boe/d (consisting of 1,400 bbl/d of light crude oil and 6,000 mcf/d of conventional natural gas). The Planadas-1 exploration well, located 6.3 kilometers west of the La Belleza-1 discovery, was drilled to a measured depth of ~13,700 feet and yielded no hydrocarbons. The operator, at sole risk, proceeded with a sidetracking operation to investigate a nearby updip target.
On December 7, 2021, Frontera spud the Jandaya-1 exploration well on the Perico block (Frontera 50% W.I. and operator) in Ecuador. The well was drilled to a total depth of 10,975 feet (3,345 meters) and a total of 78 feet vertical depth of potential hydrocarbon bearing reservoir was encountered in three formations. Production tests in the lower Hollin formation have produced 780 barrels per day of 27.9 degree API crude oil and 0.582 million standard cubic feet per day of gas, for a combined 882 total boe with a 1.7% water cut, after 29 days of testing. Development planning activities and permitting work has begun in advance of long-term testing of at least six months or a longer period of time if approved by authorities. The Company is also preparing the environmental impact assessment as part of its efforts to obtain a production environmental license.
On January 28, 2022, Frontera spud its second exploration well called Tui-1 in the southern portion of the Perico block. The Tui-1 exploration well is expected to be drilled to a total depth of 10,972 feet and is targeting the same Hollin formation as Jandaya-1. Additional prospects on the Perico block have been identified and are being matured for future drilling.
In the Espejo block (Frontera 50% W.I., non-operator), the Company anticipates acquiring 60 square km of 3D seismic followed by spudding the first exploration well in the block in the second half of 2022.
As part of its risk management strategy, the Company uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect 40%-60% of the estimated production to protect the revenue generation and cash position of the Company while maximizing upside. Previously, the Company's hedging strategy included the use of a combination of capped and uncapped instruments. For 2022, Frontera has adjusted its strategy from previous years, now only using put options, which allows the Company to capture the full upside price benefit while offering efficient downside hedging.
Subsequent to December 31, 2021, the Company entered into new put hedges totaling 2,640,000 bbls to protect 2022 estimated production up to September 2022 at a $70/bbl strike price, and upgraded 565,000 existing hedges as of December 31, 2021 from a $60/bbl strike price to $70/bbl strike price. The following table summarizes Frontera's hedging position as of March 2, 2022.
Type of Instrument
Open Positions (bbl/d)
Strike Prices Put/ Call
Update on Frontera's ESG Strategy Implementation
In 2021, Frontera made significant progress implementing its "Building a Sustainable Future" ESG strategy, achieving 98% of its ESG goals for the year. In the environmental focus area, the Company neutralized 41% of its emissions through carbon credits and, preserved and restored 764 hectares of key connectivity corridors in Casanare and Meta departments, Colombia and continued maintenance activities on an additional 783 hectares the Company had previously restored.
In the social focus area, Frontera was awarded the Equipares Gold Seal for the Company's commitment and efforts to close gender gaps in the workplace and in the communities where it operates. The Company also strengthened its local supplier programs and increased the purchase of local goods and services to $40 million. Frontera continues to build a strong HSE culture, achieving a total reportable incident rate of 1.70 for the year.
In the governance focus area, Frontera was recognized in 2021 for the first time as one of the World's Most Ethical Companies by Ethisphere, a leader in the promotion of business ethics. The Company continues to improve its ethics, integrity, compliance, and responsible risk management standards and remains committed to develop its ESG risk management processes across the Company.
Fourth Quarter 2021 Conference Call Details
A conference call for investors and analysts will be held on Thursday, March 3, 2022 at 10:00 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Alejandro Piñeros, Chief Financial Officer and other members of the senior management team.
Analysts and investors are invited to participate using the following dial-in numbers:
Participant Number (Toll Free North America): 1-888-204-4368
Participant Number (Toll Free Colombia): 01-800-518-3328
Participant Number (International): 1-647-794-4605
Conference ID: 9418837
Webcast Audio: www.fronteraenergy.ca
A replay of the conference call will be available until 11:59 p.m. Eastern Time on March 10, 2022.
Encore Toll free Dial-in Number: 1-647-436-0148
International Dial-in Number: 1-888-203-1112
Encore ID: 9418837
Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 34 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner.
If you would like to receive news releases via email as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.
Cautionary Note Concerning Forward-Looking Statements
This news release contains forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to activities, events or developments that the Company believes, expects or anticipates will or may occur in the future. Forward-looking information in this news release includes, without limitation, statements relating to anticipated well results and additional analysis being conducted on well data; the impact of the Kawa-1 exploration well results on the development plans for the Wei-1 exploration well; CGX's assessment of several strategic opportunities to obtain additional financing to meet its current and future needs; expectations of the Guyana Government with respect to the Demerara block; anticipated exploration, development and drilling activities and seismic acquisition; expectations with respect to the Company's hedging strategy; expectations with respect to releasing additional restricted cash in the second quarter of 2022; and activities and expectations regarding the Company's ESG strategy. All information other than historical fact is forward-looking information.
Forward-looking information reflects the current expectations, assumptions and beliefs of the Company based on information currently available to it and considers the Company's experience and its perception of historical trends, including expectations and assumptions relating to commodity prices and interest and foreign exchange rates; the current and potential adverse impacts of the COVID-19 pandemic, including the status of the pandemic and future waves and any associated policies around current business restrictions; the performance of assets and equipment; the availability and cost of labour, services and infrastructure; the execution of exploration and development projects; the receipt of any required regulatory approvals and outcome of discussions with governmental authorities; and the success of the Company's hedging strategy; and the impact and success of the Company's ESG strategies.
Although the Company believes that the assumptions inherent in the forward-looking information are reasonable, forward-looking information is not a guarantee of future performance and accordingly undue reliance should not be placed on such information. Forward-looking information is subject to a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to the Company. The actual results may differ materially from those expressed or implied by the forward-looking information, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. The Company's annual information form dated March 2, 2022, its annual management's discussion and analysis for the year ended December 31, 2021, and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge by referring to the company's profile on SEDAR at www.sedar.com. All forward-looking information speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking information, whether as a result of new information, future events or results or otherwise.
Non-IFRS Financial Measures
This news release contains financial terms that do not have standardized definitions in International Financial Reporting Standards ("IFRS"): Operating EBITDA, Operating Netback, Net Sales, Oil and gas sales, net of purchases, Consolidated Total Indebtedness and Net Debt. These financial measures, together with measures prepared in accordance with IFRS, provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. The Company's determination of these non-IFRS measures may differ from other reporting issuers, and therefore are unlikely to be comparable to similar measures presented by other companies. Further, these non-IFRS measures should not be considered in isolation or as a substitute for measures of performance or cash flows prepared in accordance with IFRS.
EBITDA is a commonly used measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and depletion, depreciation and amortization expense.
Operating EBITDA represents the operating results of the Company's primary business, excluding the items noted above, restructuring, severance and other costs, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, costs under terminated pipeline contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company.
A reconciliation of net income (loss) to operating EBITDA is as follows:
Three Months Ended
Net income (loss)
Income tax (recovery) expense
Depletion, depreciation and amortization
Impairment (reversal) expense and others
Cost under terminated pipeline contracts
Shared-based compensation non-cash portion
Restructuring, severance and other costs
Share of income from associates
Foreign exchange loss (gain)
Other (income) loss, net
Unrealized (gain) loss on risk management contracts
Loss on extinguishment of debt
Reclassification of currency translation adjustments
Operating Netback and Oil and Gas Sales, Net of Purchases
Operating netback is used to assess the net margin of the Company's production after subtracting all costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its midstream segment from the per barrel metrics. Refer to the reconciliation in the "Operating Netback" section on page 11 of the MD&A.
Refer to the "Operating Netback and Oil and Gas Sales, Net of Purchases" section on pages 23 and 24] of the MD&A for a description of each component of the Company's operating netback and how it is calculated.
Oil and gas sales, net of purchases, on a per boe basis is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining cost, divided by the total sales volumes from D&P assets, net of purchases. Refer to the reconciliation in the "Operating Netback and Oil and Gas Sales, Net of Purchases'' section on pages 23 and 24 of the MD&A.
Net sales are a non-IFRS subtotal that adjusts revenue to include realized gains and losses from risk management contracts while removing the cost of dilution activities. This is a useful indicator for management as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these risk management activities. The deduction for dilution costs and cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from production net of dilution, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil & gas segment. Refer to the reconciliation in the "Sales" section on page 12 of the MD&A.
Consolidated Total Indebtedness and Net Debt
Consolidated total indebtedness and net debt are used by the Company to monitor its capital structure, financial leverage, and as a measure of overall financial strength. Consolidated total indebtedness is defined as long-term debt, plus liabilities for leases and net position of risk management contracts, excluding Unrestricted Subsidiaries. This metric is consistent with the definition under the Company's Indenture (as defined in the MD&A) for the calculation of certain conditions and covenants. Net debt is defined as consolidated total indebtedness less cash and cash equivalents. Both measures are exclusive of non-recourse subsidiary debt and certain amounts attributable to the Unrestricted Subsidiaries. Refer to the reconciliation in the "Consolidated Total Indebtedness and Net Debt" section on page 24 of the MD&A for additional information about these financial measures.
Oil and Gas Information Advisories
Reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.
The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy.
Barrel(s) of oil
Barrels of oil per day
Refer to "Boe Conversion" disclosure above
Barrel of oil equivalent per day
Thousand cubic feet
Net production represents the Company's working interest volumes, net of royalties and internal consumption
SOURCE Frontera Energy Corporation